The present invention lies in the field of additives to wellbore fluids used while drilling wells in earth formations, completion operations after the drilling has been completed, workover, fracturing, and various other operations in a wellbore, that is, all of those fluids which are employed over the course of the life of a well.
Particularly, the invention is concerned with stabilized additives to non-clay wellbore fluids such as various brines and emulsions of water and oil, more particularly the invention relates to additive compositions for use in wellbore fluids and to wellbore fluid containing these additive compositions.
Generally wellbore fluids will be either clay-based or brines which are clay free. Fresh water systems are sometimes used, but the brines have certain advantages which are discussed below. These two classes are exclusive, that is, clay-based drilling fluids are not brines. A wellbore fluid can perform any one or more of a number of functions. For example, the drilling fluid will generally provide a cooling medium for the rotary bit and a means to carry off the drilled particles. Since great volumes of drilling fluid are required for these two purposes, the fluids have been based on water. Water alone, however, does not have the capacity to carry the drilled particles from the borehole to the surface.
In the drilling fluid class, clay-based fluids have for years preempted the field, because of the traditional and widely held theory in the field that the viscosity suitable for creating a particle carrying capacity in the drilling fluid could be achieved only with a drilling fluid having thixotropic properties, that is, the viscosity must be supplied by a material that will have sufficient gel strength to prevent the drilled particles from separating from the drilling fluid when agitation of the drilling fluid has ceased, for example, in a holding tank at the surface.
In order to obtain the requisite thixotropy or gel strength, hydratable clay or colloidal clay bodies such as bentonite or fuller's earth have been employed. As a result the drilling fluids are usually referred to as "muds". In other areas where particle carrying capacity may not be as critical, such as completion or workover, brine wellbore fluids are extensively employed. The use of clay-based drilling muds has provided the means of meeting the two basic requirements of drilling fluids, i.e., cooling and particle removal. However, the clay-based drilling muds have created problems for which solutions are needed. For example, since the clays must be hydrated in order to function, it is not possible to employ hydration inhibitors, such as calcium chloride, or if employed, their presence must be at a level which will not interfere with the clay hydration. In certain types of shales generally found in the Gulf Coast area of Texas and Louisiana, there is a tendency for the shale to disintegrate by swelling or cracking upon contact with the water, if hydration is not limited. Thus the uninhibited clay-based or fresh water drilling fluids may be prone to shale disintegration.
The drilled particles and any heaving shale material will be hydrated and taken up by the conventional clay-based drilling fluids. The continued addition of extraneous hydrated solid particles to the drilling fluid will increase the viscosity and necessitated costly and constant thinning and reformulation of the drilling mud to maintain its original properties.
Another serious disadvantage of the clay-based fluids is their susceptibility to the detrimental effect of brines which are often found in drilled formations, particularly Gulf Coast formations. Such brine can have a hydration inhibiting effect, detrimental to the hydration requirement for the clays.
A third serious disadvantage of clay-based drilling fluids arise out of the thixotropic nature of the fluid. The separation of drilled particles is inhibited by the gel strength of the drilling mud. Settling of the drilled particles can require rather long periods of time and require settling ponds of large size.
Other disadvantages of clay-based drilling fluids are their (1) tendency to prevent the escape of gas bubbles, when the viscosity of the mud rises too high by the incidental addition of hydratable material, which can result in blowouts; (2) the ned for constant human control and supervision of the clay-based fluids because of the expectable, yet unpredictable, variations in properties; and (3) the formation of a thick cake on the internal surfaces of the wellbore.
Fresh water wellbore fluids avoid many of the clay-based fluid problems, but may cause hydration of the formation. The brines have the advantage of containing hydration inhibiting materials such as potassium chloride, calcium chloride or the like. Quite apparently any solid particulate material would be easily separated from the brine solution since it is not hydrated. Thus, the properties of the brine are not changed by solid particulate matter from the wellbore. Similarly, since there is no opportunity for gas bubbles to become entrapped, blowouts are less likely in a clay-free brine-type wellbore fluid.
Thus, the wellbore art now has two competing and incompatible water based systems which can be used in a full range of wellbore operations, i.e., the problem plagued clay-based wellbore fluids or the improved clay-free wellbore fluids, principally brines. In many areas of application, as noted above, clay-free brines are already the usual selection.
Quite frequently guar gum has been used as a water loss control agent in wellbore fluids, in the same manner as starch, other natural gums, such as karaya, psyllium, tragacanth, talha, locust bean, ghatti and the like, cellulosic derivatives, such as carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, synthetic polymers such as polyacrylic acid, polyethylene glycol etc. However, the stability of these materials has been a continuing problem, which usually means early and frequent make up of the water loss control material in wellbore operations.
When a non-clay wellbore fluid is used for a purpose requiring relatively high viscosity, for example drilling, it is generally necessary to employ an additive to thicken the fluid to the point where it will have the necessary carrying capacity. Several additives to increase viscosity are commercially available, but most if not all of these have one or more limitations. The viscosifier may be slow to yield, i.e., it may take 15 minutes or more from the time of addition to the time when the fluid becomes thick enough to carry the cuttings. The additives may be effective over only a narrow low temperature range, permitting the fluid to thin out again when a higher temperature is reached. In addition, most of the viscosifiers have a limited service life, again thinning out after a period of use.
Many of the water loss additives have been found to be suited for providing non-structured viscosity to non-clay wellbore fluids. Guar gum and/or hydroxyalkyl guar gum can provide non-structured, i.e., non-thixotropic viscosity to wellbore fluids. These materials are water soluble and nonionic, thus they are not susceptible to being expelled from a brine solution, for example as are the soluble salts of carboxymethyl cellulose. The term "non-structured viscosity" as used here means one wherein viscosity is obtained by physio-chemical rather than by physical means. Asbestos and attapulgite are examples of the types of materials employed to obtain structured viscosity.
The non-structured viscosity provides another unique benefit in that the carrying capacity will vary in the agitated and non-agitated states, so that when, for example, the agitation is reduced in a separating tank the carrying capacity will drop off and the cuttings and the like from the wellbore will fall out of the fluid, yet when agitated there is ample carrying capacity to carry the cuttings and the like to the surface from the wellbore.
It is an advantage of the present additive compositions that they have extended stability and effectiveness over a higher temperature range. A particular feature is that faster yields are obtained by using the additive composition in wellbore fluids. A particular advantage of the present additive composition is that the water loss effectiveness is greater, and is extended beyond that normally achieved with guar gum and hydroxyalkyl guar gum. These and other advantages and features of the present invention will be apparent from the disclosure, descriptions and teachings set out below.